Fracturing is commonly done is horizontal or nearly horizontal completions. Initially the toe of the well is perforated and fractured. After that a frac plug with a perforating gun are run together and the plug is set with a known setting tool secured to it which then releases from it. The gun is released from the set plug and shot. The previously fractured zone at the toe of the well is isolated by pumping a ball to the set frac plug after the gun has been tripped out. The frac plug typically has a passage through a tubular mandrel and a seat for a ball or a dart to land on and obstruct the zone below that has already been fractured. The next zone above the toe is then fractured and the process is repeated until the entire interval has been fractured. The well can then be put into production.
The structure and operation of a known frac plug design is described below in association with FIGS. 1-3.
The operation of frac plug 10 is as follows. Frac plug 10 may be lowered into the wellbore 25 utilizing a setting tool of a type known in the art. As is depicted schematically in FIG. 1, one, two or several frac plugs or downhole tools 10 may be set in the hole. As the frac plug 10 is lowered into the hole, flow therethrough will be allowed since the spring 82 will prevent sealing ball 38 from engaging ball seat 50, while ball cage 36 prevents sealing ball 38 from moving away from ball seat 50 any further than upper end cap 90 will allow. Once frac plug 10 has been lowered to a desired position in the well 20, a setting tool of a type known in the art can be utilized to move the frac plug 10 from its unset position 32 to the set position 15 as depicted in FIGS. 2 and 3, respectively. In set position 15 slip segments 56 and expandable packer elements 66 engage casing 30. It may be desirable or necessary in certain circumstances to displace fluid downward through ports 92 in ball cage 36 and thus into and through longitudinal central flow passage 48. For example, once frac plug 10 has been set it may be desirable to lower a tool into the well, such as a perforating tool, on a wire line. In deviated wells it may be necessary to move the perforating tool to the desired location with fluid flow into the well. If a sealing ball has already seated and could not be removed therefrom, or if a bridge plug was utilized, such fluid flow would not be possible and the perforating or other tool would have to be lowered by other means.
When it is desired to seat sealing ball 38, fluid is displaced into the well at a predetermined flow rate which will overcome a spring force of the spring 82. The flow of fluid at the predetermined rate or higher will cause sealing ball 38 to move downwardly such that it engages ball seat 50. When sealing ball 38 is engaged with ball seat 50 and the plug 34 is in its set position 15, fluid flow past frac plug 10 is prevented. Thus, slurry or other fluid may be displaced into the well 20 and forced out into a formation above frac plug 10. The position shown in FIG. 3 may be referred to as a closed position 94 since the longitudinal central flow passage 48 is closed and no flow through frac plug 10 is permitted. The position shown in FIG. 2 may therefore be referred to as an open position 96 since fluid flow through the frac plug 10 is permitted when the sealing ball 38 has not engaged ball seat 50. As is apparent, sealing ball 38 is trapped in ball cage 36 and is thus prevented from moving upwardly relative to the ball seat 50 past a predetermined distance, which is determined by the length of the ball cage 36. The spring 82 acts to keep the sealing ball 38 off of the ball seat 50 such that flow is permitted until the predetermined flow rate is reached. Ball cage 36 thus comprises a retaining means for sealing ball 38, and carries sealing ball 38 with and as part of frac plug 10, and also comprises a means for preventing sealing ball 38 from moving upwardly past a predetermined distance away from ball seat 50.
When it is desired to drill frac plug 10 out of the well, any means known in the art may be used to do so. Once the drill bit 13 connected to the end of a tool string or tubing string 16 has gone through a portion of the frac plug 10, namely the slip segments 56 and the expandable packer elements 66, at least a portion of the frac plug 10, namely the lower end 14 which in the embodiment shown will include the mule shoe 70, will fall into or will be pushed into the well 20 by the drill bit 13. Assuming there are no other tools therebelow, that portion of the frac plug 10 may be left in the hole. However, as shown in FIG. 1, there may be one or more tools below the frac plug 10. Thus, in the embodiment shown, ceramic buttons 93 in the upper frac plug 10a will engage the upper end 12 of lower frac plug 10b such that the portion of upper frac plug 10a will not spin as it is drilled from the well 20. Although frac plugs 10 are utilized in the foregoing description, the ceramic buttons 93 may be utilized with any downhole tool such that spinning relative to the tool therebelow is prevented.
The mandrel that has the ball seat 50 that accepts the ball 38 is typically a filament wound composite tube with a wall thickness sufficient to resist collapse in the set position when the seal 66 is against the surrounding tubular in a compressed condition and retained by the slips 56, 57. The tubular mandrel is preferably made of readily drillable materials but in order to meet its structural requirements when the frac plug is set winds up being a significant cost driver in the cost of fabrication of the frac plug assembly. While frac plug designs can vary, as illustrated in U.S. Pat. Nos. 6,394,180; 6,491,116; 7,740,079; US Publication 2008/0271898; 2011/0290473; 2011/0315403; 2011/0048740 and 2011/0240295, they all need to meet the requirement of allowing some flow through the tools so that fluid displacement can occur and they all need the structural rigidity to resist collapse from pressure loading and the set sealing element.
Numerous frac plugs can be used in a given well and as a result they are used in large quantities throughout the world and have approached the status of a commodity product with very competitive pricing. Accordingly it is desirable to reduce the manufactured cost of these plugs and the present invention addresses this issue by providing design alternatives to the most expensive component which is the mandrel and associated ball seat. Rather than the prior designs of a relatively thick wall tubular the present invention envisions a porous internal structure that has substantial capacity to resist compressive loading that can then be surrounded with a thinner outer tubular that merely acts to distribute the compressive loading that is borne by the internal structure. Various internal structures are envisioned such as a star pattern of a series of radially extending members from a central solid hub, a honeycomb cylindrical shape or a screw shape defining a helical flow path, among other variations. Those skilled in the art will more readily appreciate other aspects of the invention from a review of the description of the preferred embodiment and the associated drawings while understanding that the full scope of the invention is to be determined from the appended claims.